Under-Balanced Drilling
When drilling oil or gas wells, it is often desirable to drill certain formations in an under-balanced condition. Under-balanced drilling means that the hydrostatic column of drilling fluid is less than the reservoir pressure of the formation being drilled. Drilling under-balanced can be especially important when drilling horizontal wells in coal seams.
Coal seams typically possess certain permeability due to a natural cleat system. Under-balanced drilling is important in order to protect that permeability. If a coal seam well is drilled over-balanced, drilling fluid, and the solid material within the drilling fluid, can invade the cleat system of the coal. This will cause damage to the natural permeability and will likely hinder future gas production. Another problem associated with overbalanced drilling is “lost circulation”. This can be a problem in horizontal coal wells particularly after a large amount of horizontal footage has already been drilled. As drilling fluid is lost into the formation, it may be impossible to keep adequate drilling fluid returning to the surface, thus affecting both hole-cleaning, as well as the ability to maintain an adequate supply of drilling fluid at the rig site. Also related to lost circulation is the phenomenon known as differential sticking. When a negative pressure differential exists between the borehole and the formation, the drill pipe can become stuck against the wall of the wellbore.
There are a number of under-balanced drilling methods available. Frequently, a gas phase drilling fluid is selected. Compressible fluids such as air or nitrogen are usually mixed with small amounts of liquids to form a mist or foam. Another method of under-balanced drilling involves the use of what is commonly called a parasite string. A parasite string refers to an extra conduit that is installed in a well and used to inject a gas at a certain location in the well in order to reduce the density of the liquid drilling mud returns. From the point where the gas is injected, the fluid returning to the surface becomes less dense, and the hydrostatic pressure on the formation can be reduced to an under-balanced condition.
Use of Parasite Strings in Under-Balanced Drilling
Parasite strings are ideally suited for use in under-balance drilling operations since the primary drilling fluid flowing through the bit remains a non-compressible liquid drilling mud. The non-compressible nature of liquid drilling mud allows the use of simple, low-cost mud-pulse telemetry equipment to communicate with any down-hole survey instruments that are necessary for guidance while drilling directional or horizontal wells. Yet another benefit of mud-based fluids is that, compared to low viscosity fluids such as gases, foams, or mists, drilling mud has far superior hole-cleaning properties. Additionally, when compressible gas drilling fluids are used to power progressing cavity down-hole motors, fluctuation in weight on the bit can cause large fluctuations in the speed of the motor. High motor speeds and the associated motor vibration can significantly damage or reduce the life of the electronic guidance systems.
Numerous parasite configurations have been employed in the past. In some cases, a tubing string is run in the well alongside the casing, and both are then cemented into place. In another configuration, an annulus formed by an additional inner casing string forms the necessary conduit to convey the gas to the injection point. While both of these configurations can functionally form the additional gas conveying conduit, in either case, a larger borehole diameter and a larger curve radius are required when compared to a non-parasite well configuration.
As an example and referring to FIG. 1, consider a conventional horizontal well 110 that does not employ the use of a parasite string. The well 110 may be drilled with a drill bit 112 having a cutting diameter of 6¼ inches. The drill bit 112 is operably attached to a drill string 114. Drilling fluids are pumped through the drill string 114 by a mud pump 116 to turn the drill bit 112. Based on the size of the drill bit 112, a vertical section 118 that is 8¾ inches in diameter is drilled from a surface 120 of the well 110 to a point where a curved section 124 of the well 110 will begin, approximately 150 feet above a target formation 128. A casing 132 having a diameter of 7 inches is positioned in the vertical section 118 and cemented into place. A 6¼ inch hole is then be drilled out of the 7 inch casing 132 to create the curved section 124. In this particular example, the curved section 124 has a radius R, that is about 150 feet. Once the drill bit assumes a horizontal orientation, drilling with the 6¼ inch drill bit 112 continues to create a horizontal section 136. The horizontal section 136 extends a desired distance or until the target formation 128 is reached.
Referring to FIG. 2, a well 210 having a traditional parasite string configuration is illustrated. The well 210 includes a vertical section 216, a curved section 224, and a horizontal section 236 similar to well 110 of FIG. 1. In the illustrated example, it is desirable to inject a gas at a heel 211 of the curved section 224. The gas is provided by a compressor 215 to a parasite string 240 concentrically positioned around a drill string 214. The drill string 214 is attached to a drill bit 212 that is used to drill the well 210. In conventional parasite string configurations, the parasite string 240 is sized to allow the drill bit 212 to pass through the parasite string 240. This allows the drill string 214 and drill bit 212 to be removed from the well 210 without removing the large-diameter parasite string 240.
In the example illustrated in FIG. 2, the drill bit 212 is sized the same as the drill bit 112 of FIG. 1, namely to provide a cutting diameter of 6¼ inches. The parasite string 240 is sized to be 7 inches in diameter to allow the drill bit 212 to pass through the parasite string 240. Because of the rigidity of the 7 inch, steel-casing parasite string 240, the curved section 224 of the well 210 must have a radius, R, of 500 feet instead of the 150 foot radius associated with well 110 of FIG. 1. In addition, because the 7 inch parasite string 240 is now an inner string, an outer casing 244 having a diameter of 9⅝ inches must now be set. A further problem arises in selecting a hole-diameter for the curved section 224. Conventionally, an 8¾ inch bit would be selected to drill out of the 9⅝ inch outer casing 244; however, this size hole would not provide adequate clearance for the collars (i.e. couplings) associated with the 7 inch parasite string 240. As such, a hole opener is run below the outer casing 244 to enlarge the curved section 224 of the well 210 below the outer casing 244 from 8¾ inches to approximately 10 inches.
The alternate configuration of utilizing a non-concentric gas injection tubing string alongside the 7 inch casing provides no greater savings in efficiency. In this configuration, both a 7 inch casing and a 2⅜″ gas injection string are connected and simultaneously run into the well side-by-side (not shown). Unfortunately, compared to non-parasite drilling well configurations, enlarged hole-sizes are again required to accommodate a 2⅜ inch tubing string beside the 7 inch parasite string 240. There are also complications in running the relatively fragile tubing beside the 7 inch casing.
Extended Reach Drilling
Extending the reach of a horizontal well is a cost efficient method of adding additional production and reserves to the well for a relatively small incremental drilling cost. This is particularly true for horizontal wells, where the fixed cost components of drilling the well, such as building the access road and location, constructing surface facilities, setting surface casing and drilling the curve to horizontal, can easily exceed the cost of drilling the horizontal section of the well. Most often, the ultimate length that a well can be drilled is determined by the friction of the drill pipe rotating and sliding against the walls of the wellbore.
In drilling vertical wells, maintaining adequate weight on the drill bit is not a problem. In horizontal drilling however, the weight of the drill pipe in the vertical section of the well must be sufficient to push the drill-pipe out into the horizontal section of the well. When the friction forces of the pipe sliding in the horizontal section of the well approaches the gravity force (weight) of the pipe in the vertical section, insufficient weight is applied to the bit, and drilling efficiency initially slows, then stops. Since coalbed methane is typically produced from shallow formations, insufficient weight on the bit frequently limits the reach or length of these wells. Various techniques are employed to extend the reach of shallow horizontal wells. These reach extending methods can be grouped into two broad categories; 1) those that reduce the friction of the drill pipe, and 2) those that increase the weight applied to the drill-pipe.
Although friction reducing chemicals such as polymers can be added to the drilling mud, there is always a risk of formation damage if these chemicals invade the fracture or cleat system of the productive formation. As such, friction reduction is most often achieved by ensuring some amount of movement of the drill-pipe. In doing so, the friction that must be overcome is the kinetic or dynamic friction rather than static friction. Dynamic friction of the drill pipe in motion is typically only 60%-70% of the static friction of drill pipe at rest. Rotary-steerable directional drilling systems are available that allow the well to be directionally steered while the drill-pipe remains in constant rotational motion. These systems perform well, but they are relatively expensive to build and maintain.
More commonly, horizontal drilling utilizes a down-hole motor with an oriented bend to directionally steer the well. In order to break the static friction, frequently the driller simply “rocks” the drill pipe back-and-forth, alternating with a small amount of clockwise and counter-clockwise rotation. Although attempts have been made to automate this process, it remains a relatively imprecise technique. Further, since rotation is only applied in cycles of left, then right movement, at each direction change, movement of the drill pipe momentarily stops and static friction again prevails.
In some cases, a device can be deployed in the well that induces axial vibration into the drill-pipe. These devices are installed in the drill string and utilize a water hammer principle to agitate the drill-pipe. Although these devices can be quite efficient at creating friction-reducing vibration in the pipe, those same vibrations can cause damage to the electronic equipment used for guidance and telemetry in steering the well.
All references cited herein are incorporated by reference.